This section is intended to introduce various aspects of the art, which may be associated with exemplary embodiments of the present invention. This discussion is believed to assist in providing a framework to facilitate a better understanding of particular aspects of the present invention. Accordingly, it should be understood that this section should be read in this light, and not necessarily as admissions of prior art.
During oil and gas production, the presence of acid gases such as CO2 and H2S dissolved in water can cause corrosion in pipelines made from carbon steel material. While corrosion resistant alloys (CRAs) do exist, carbon steel is used predominantly for oilfield pipeline and surface facilities due to its substantially lower comparative cost.
A crude oil pipeline can transport water, gas, and crude oil in a number of different possible flow patterns, including stratified flow and dispersed flow. In stratified flow, the gas and liquids exist in separate phases that form different layers. Due to the differences in density between the two liquid phases, the water layer may segregate from the oil layer and accumulate at the bottom of the pipeline, in a regime commonly called “water wetting”. The presence of the acid gases in the water can cause the bottom inner wall of the pipeline to corrode. One method of preventing corrosion is to maintain a relatively high flow velocity, which can cause the water to be entrained as droplets in the flowing oil phase, which is known as dispersed flow. This method allows the oil, which is typically not corrosive to carbon steel, to maintain contact with the pipeline wall, resulting in an “oil wetting” regime. Under certain flow conditions, both oil and water phases can make contact with the bottom pipeline wall, resulting in an “intermittent wetting” regime. The corrosion rate of the pipeline wall may depend on both environmental conditions such as temperature and partial pressures of acid gases as well as phase wetting regimes.
Presently, the multi-phase flow of oil-water can be simulated using a large scale flow loop. In a large scale flow loop, an oil-water mixture is pumped through a pipeline loop to simulate multi-phase flow patterns occurring in the oilfield pipeline, such as stratified, dispersed, and slug flow. Contained within the flow loop are various instruments that can monitor phase wetting, fluid velocity, and corrosion during the multi-phase flow. However, large scale flow loops may require several days to prepare and a few hundred gallons of oil water to properly simulate flow. They may also require a large amount of space to operate.
Another alternative is an autoclave. An autoclave is a high-temperature, high-pressure reaction vessel that can be used to simulate field conditions. An autoclave has a smaller form factor, and requires significantly less time to prepare and fewer resources to operate. Prior to operation, the autoclave is filled with an oil-water mixture, with the oil forming a layer on top of the water. In present embodiments, a rotor shaft connected to a set of turbine blades or coupon ports is rotated. This action stirs up the water layer and creates turbulence in the oil-water mixture. Various instruments may be implemented to monitor parameters such as corrosion, fluid velocity, and phase wetting. However, this operation may not be representative of real flow patterns and proper oil/water phase wetting occurring in field pipelines, as the rotation of the turbine blades or coupon ports creates an emulsion or well-mixed fluid, rather than stratified flow or dispersed flow. In emulsive or well-mixed flow, either water is dispersed in oil or oil is dispersed in water homogenously as droplets.
A technology for more accurate simulation of pipeline flow would benefit oil and gas production. Such a technology would help by simulating field conditions to measure corrosion.